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entitled 'Bonneville Power Administration: Better Management of BPA's
Obligation to Provide Power Is Needed to Control Future Costs' which
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Report to the Subcommittee on Energy and Water Development, Committee
on Appropriations, House of Representatives:
United States General Accounting Office:
GAO:
July 2004:
Bonneville Power Administration:
Better Management of BPA's Obligation to Provide Power Is Needed to
Control Future Costs:
GAO-04-694:
GAO Highlights:
Highlights of GAO-04-694, a report to the Subcommittee on Energy and
Water Development, Committee on Appropriations, House of
Representatives:
Why GAO Did This Study:
The Bonneville Power Administration (BPA) has experienced significant
financial problems in recent years. BPA’s cash reserves at the end of
fiscal year 2002 had fallen to $188 million, and BPA estimated in
February 2003 that it had a 74 percent chance of missing its Treasury
debt payment that year. While BPA’s finances have recently improved,
and the agency made its Treasury payment in 2003, BPA’s financial
condition is still far from robust. In this context, GAO was asked to
report on (1) the advantages and disadvantages BPA faces in marketing
electric power in a more competitive environment, (2) the major causes
of BPA’s recent cost increases, and (3) the extent to which BPA is
taking actions to control its costs.
What GAO Found:
BPA has advantages that have typically enabled it to sell electric
power to its customers—primarily public utilities—at lower prices than
other sellers in the Pacific Northwest. Most importantly, BPA sells
power produced by the federal power system, which includes 31
hydroelectric dams that generally have lower costs as compared with
other power sources. However, BPA also has disadvantages that
potentially increase its costs. Specifically, BPA is required by law
to meet the demands of utilities in the region, even if those demands
exceed the production capacity of the federal power system. This
open-ended requirement has at times required BPA to purchase additional
power at relatively high prices. BPA has other costly obligations as
well, including providing financial benefits to investor-owned
utilities and protecting fish and wildlife that increase its costs
relative to competing sources of electricity.
BPA’s open-ended obligation to provide power to the region is the major
cause of its recent cost increases. This obligation led to cost
increases as BPA purchased large amounts of relatively expensive power
to meet rising demand. BPA’s rate structure also contributed to
increased demand and increased costs, because it did not reflect BPA’s
incremental costs of acquiring additional power and therefore did not
give customers adequate incentives to conserve or seek power from
alternative sources. In addition, drought and other factors have also
increased BPA’s costs in recent years.
BPA has not resolved problems associated with its open-ended obligation
to be the net provider of wholesale electricity in the region—the major
cause of its recent cost increases. BPA officials intend to resolve
this problem by seeking agreement with BPA’s customers to limit its
commitment to provide power. BPA proposes to establish the amount of
power each customer is able to buy at its lowest cost-based rate and is
considering charging incremental rates for any power it sells beyond
this amount. However, BPA has not clearly defined the limits for its
commitments or how it would implement incremental rates. Whether this
approach ultimately will be adopted is also unclear; BPA had similar
plans in the late 1990s but did not implement them because of pressure
from customers to serve more demand. In the meantime, BPA has taken
positive steps to centralize its risk management process to better
control costs. However, BPA’s plan outlining its new approach does not
contain some key elements to successful implementation, including
details on specific activities, resources, and time frames needed to
implement the plan.
What GAO Recommends:
GAO recommends that BPA
* reduce its future risk of being overcommitted by (1) limiting
the amount of power that BPA sells at its lowest cost-based rate and
(2) charging incremental rates for any power sold beyond this amount
that reflect BPA’s cost of acquiring that power, and
* identify specific activities, resources, and time frames for
implementing its risk management initiatives.
BPA generally agreed with this report’s findings and recommendations.
www.gao.gov/cgi-bin/getrpt?GAO-04-694.
To view the full product, including the scope and methodology, click on
the link above. For more information, contact Jim Wells at (202) 512-
3841 or wellsj@gao.gov.
[End of Section]
Contents:
Letter:
Results in Brief:
Background:
Inherent Advantages Help BPA to Provide Low-Priced Power, but Its Open-
ended Obligations Are a Competitive Disadvantage:
BPA's Open-ended Obligation to Provide Power and Other Factors Led to
Large Cost Increases for BPA:
BPA Has Not Resolved Problems That Led to Its Recent Cost Increases,
but It Has Taken Steps to Control Other Costs:
Conclusions:
Recommendations for Executive Action:
Agency Comments:
Appendix I: Scope and Methodology:
Appendix II: BPA's Costs Associated with Fish and Wildlife Programs:
Appendix III: BPA Costs Associated with Its Power Marketing Business,
Fiscal Years 1997-2003:
Appendix IV: Comments from the Bonneville Power Administration:
Appendix V: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Staff Acknowledgments:
Tables:
Table 1: BPA's Costs Associated with Fish and Wildlife Programs, Fiscal
Years 1985-2003:
Table 2: BPA Costs Associated with Its Power Marketing Business, Fiscal
Years 1997-2003:
Figures:
Figure 1: Average Monthly Prices for Wholesale Electricity in the
Pacific Northwest, 1997-2003:
Figure 2: Average Production Costs for Different Types of Generating
Plants in Idaho, Oregon, Washington, and Western Montana, 1996-2002:
Figure 3: Average Wholesale Prices for Electricity Sold by BPA and the
Five Largest Investor-Owned Utilities in the Pacific Northwest, 1996-
2002:
Figure 4: Average Retail Prices of Electricity, 1996-2002:
Figure 5: BPA's Average Power Rates, Fiscal Year 1972-2001:
Figure 6: Power Purchased and Power Contracts Signed by BPA's Major
Customer Groups, Fiscal Year 1993-2006:
Figure 7: Major Events and Electricity Prices during BPA's Subscription
and Ratemaking Processes:
Abbreviations:
aMW: average megawatt:
BPA: Bonneville Power Administration:
FERC: Federal Energy Regulatory Commission:
MWh: megawatt-hour:
United States General Accounting Office:
Washington, DC 20548:
July 9, 2004:
The Honorable David L. Hobson:
Chairman:
The Honorable Peter J. Visclosky:
Ranking Minority Member:
Subcommittee on Energy and Water Development:
Committee on Appropriations:
House of Representatives:
The Bonneville Power Administration (BPA), which markets about 45
percent of all electric power consumed in the Pacific Northwest, has
experienced significant financial problems over the past few years.
BPA's core business of selling power lost more than $300 million each
year in fiscal years 2001 and 2002, primarily as a result of increased
costs. As a result, its cash reserves of $811 million at the end of
fiscal year 2000 had fallen to $188 million by the end of fiscal year
2002. In February 2003, BPA announced that it had an estimated 74
percent chance of missing its repayment of Treasury debt that year.
These difficulties have necessitated increases totaling more than 40
percent in the rates BPA charges its customers for power since October
2001. In large part because of these increased rates and, consequently,
greater revenues, BPA's financial condition has recently improved. BPA
made its Treasury debt payment in 2003, and its cash reserves have
risen above $500 million. However, BPA has stated that its financial
health is still far from robust, and BPA's ability to manage its costs
and risks has come under scrutiny from customers and stakeholders.
BPA was formed in 1937 to market electric power produced by the
Bonneville Dam to the Pacific Northwest. BPA's marketing
responsibilities have since broadened to include power from 31
federally owned hydroelectric projects, most located in the Columbia
River Basin. BPA also markets power from one nonfederal nuclear plant.
The 31 federal dams along with the nonfederal nuclear plant are
collectively referred to in this report as the federal power system.
While BPA markets the power produced, other entities are responsible
for operating the system--the Army Corps of Engineers and the Bureau of
Reclamation operate the hydroelectric dams; and Energy Northwest, a
consortium of utilities, operates the nuclear plant. The dams in the
federal power system are operated for flood control, irrigation,
navigation, and recreational benefits as well as for the production of
hydroelectric power. In addition, the river system is home to many
species of fish and wildlife, including some protected by the
Endangered Species Act.
BPA sells some of the power from the federal power system, at cost-
based rates designed to recover BPA's full costs, via long-term
contracts with its customers in the Pacific Northwest--primarily public
utilities and large industrial facilities such as aluminum smelters in
Idaho, Montana, Oregon, and Washington. BPA distributes this power to
its customers largely on transmission lines that BPA owns and operates,
which account for more than 75 percent of the region's transmission
lines. When the federal power system generates more power than BPA has
committed to provide its customers at its cost-based rates--for
example, when spring run-off allows large volumes of hydroelectricity
to be generated--BPA sells this surplus or "secondary" power to
utilities and other entities in the Pacific Northwest and other western
states. However, at times when the electricity generation of the
federal power system is insufficient to meet BPA's commitments to its
customers, BPA purchases or otherwise acquires power from other
generators to make up the difference. Because of the variability in the
amount of water resources and therefore available power, BPA generally
considers, for planning purposes, the "firm" output of the federal
power system to be only the amount of power that can be produced in a
low or "critical" water year.[Footnote 1]
BPA is one of four power marketing administrations within the U.S.
Department of Energy.[Footnote 2] Unlike the other power marketing
administrations, BPA does not receive annual appropriations from
Congress; instead, BPA is a self-financing agency whose revenues are
generated through its sale of power and transmission services. In the
past, federal money was appropriated to construct the generating and
transmission projects from which BPA markets power, and BPA currently
repays these appropriations on an annual basis. As of September 30,
2003, the outstanding balance of BPA's appropriated debt was about $4.7
billion. BPA also has authority to borrow up to an additional $4.45
billion from the Treasury on an ongoing basis; as of September 30,
2003, BPA had about $2.7 billion of additional Treasury debt.
With the passage of the Pacific Northwest Electric Power Planning and
Conservation Act of 1980 (Northwest Power Act), BPA's role in the
region expanded in scope. For example, under the Northwest Power Act,
BPA became responsible for ensuring an adequate, efficient, economical,
and reliable power supply for the Pacific Northwest, which required BPA
to address growing demand in the region--something BPA had previously
not been required to do. In addition to its obligations to market and
distribute power, the Northwest Power Act, along with various other
statutes, treaties, and court cases, also requires BPA to "protect,
mitigate, and enhance fish and wildlife" resources affected by the
federal power system. BPA is also required under the Northwest Power
Act to provide benefits to residential and small-farm customers of
investor-owned utilities--these benefits have generally taken the form
of financial payments. The restructuring of national wholesale
electricity markets that began in the 1990s also changed the
competitive environment in which BPA operates. Specifically,
restructuring has created an environment with a greater degree of
competition among generators and marketers of wholesale electricity.
In light of BPA's recent financial difficulties and cost increases, you
asked us to determine (1) the advantages and disadvantages BPA faces in
marketing electric power in a more competitive environment, (2) the
major causes of BPA's recent cost increases, and (3) the extent to
which BPA is taking actions to control its costs. To answer our first
objective, we reviewed BPA documents and historical data, as well as
studies and position papers by industry experts. In addition, we
analyzed historical data on costs, regional and national power prices,
and power production at the federal hydroelectric dams. To answer our
second and third objectives, we reviewed BPA documents related to
costs, revenues, risk management practices, and rate-setting policies,
as well as studies and position papers by industry experts. Unless
otherwise noted, the financial data we obtained refer to BPA's power
business (i.e., the expenses and revenues embodied in its power rates).
We also interviewed BPA officials and collected views from BPA's
customers and stakeholders, including groups that focus on fish and
wildlife issues. In addition, we analyzed cost and rate data from BPA.
Finally, we interviewed officials from the U.S. Army Corps of
Engineers, one of the agencies that operate the dams of the federal
power system. We focused our review on the group within BPA that is
responsible for marketing power from the federal power system, and on
its costs in the current rate period, which began in fiscal year 2002.
We tested the reliability of data on generation costs in the Pacific
Northwest, and on BPA's costs and rates, and found them to be adequate
to answer the objectives of this report.
We conducted our review from August 2003 through April 2004 in
accordance with generally accepted government auditing standards. For a
more detailed discussion of the scope and methodology of our review,
see appendix I.
Results in Brief:
BPA has inherent advantages that have generally enabled it to sell
power at lower prices than other sellers of wholesale power in the
Pacific Northwest. BPA's most important competitive advantage is that
it markets electricity produced primarily at hydroelectric dams in the
federal power system, which generally have lower costs, as compared
with power produced by other sources. In addition, as a federal agency,
BPA enjoys financial advantages such as access to federally financed
debt, which generally offers lower interest rates than those available
to private-sector entities. However, unlike other sellers of wholesale
power, BPA has open-ended obligations to provide power and other
benefits to its customers and others in the Pacific Northwest that
increase its costs. In particular, unlike the other power marketing
administrations, BPA is required by its governing statutes to serve the
"net" demand of utilities in the region (that is, the demand that these
utilities cannot meet with their own generation resources) when
requested. Over time, this open-ended requirement has increased the
demands on BPA's finite resources; and at times, BPA has purchased
power from other sources to augment the generation resources of the
federal power system. Other statutory obligations that increase BPA's
costs relative to some of its competitors include providing financial
benefits to certain customers of regional investor-owned utilities and
protecting fish and wildlife. Regarding financial benefits to
residential and small-farm customers of the region's investor-owned
utilities, BPA is required to provide these benefits to off-set the
higher prices that--for historical reasons--these customers generally
pay for power, as compared with public utility customers. Regarding
fish and wildlife protection, BPA is the sole source of funding for the
Northwest Power and Conservation Council--a regional agency established
by the Northwest Power Act to balance the Northwest's environment and
energy needs, including developing a program to protect and rebuild
fish and wildlife populations affected by hydropower development in the
Columbia River Basin. In addition, the multiple-use nature of the dams
in the federal power system constrains the amount of power that BPA can
sell. For example, water diverted for irrigation purposes is generally
unavailable for generating electricity. These open-ended obligations
and constraints on the generation of power have increased pressure on
BPA over time and contributed to increases in BPA's costs relative to
the costs of competing sources of power. Specifically, BPA's costs--as
reflected in its cost-based rates--more than doubled in the 30 years
between fiscal years 1972 through 2001, when adjusted for inflation,
while the average costs of some other sources of power fell. By 1995,
as BPA reported in its 1995 Business Plan, for the first time in its
history, BPA's rates had risen to the level of the costs of other
sources of generation--namely gas-fired electricity generators.
BPA's open-ended obligation to be the net provider of wholesale power
to the region is the major cause of its recent cost increases. This
obligation led to BPA's overcommitment to provide power to its
customers in the current rate period--from fiscal years 2002 to 2006--
and consequently, to BPA's cost increases as it purchased large amounts
of power at average prices much higher than the costs of the federal
power system. The demand from BPA's public utility customers in the
current rate period increased by more than 50 percent over the previous
rate period--a demand that BPA is statutorily required to serve. BPA
also agreed to provide power to investor-owned utilities and large
industrial customers, although BPA was not statutorily required to do
so. To meet this increased level of demand, BPA spent approximately
$900 million in fiscal year 2002 and $760 million in fiscal year 2003,
necessitating a rate increase of more than 40 percent for the majority
of BPA's customers. BPA's rate structure also contributed to the
increase in demand and increased costs, because BPA did not charge
incremental rates equal to its costs of acquiring additional power and
therefore did not give customers adequate incentives to conserve or
seek power from alternative sources. In addition, drought conditions
and other factors have also increased BPA's costs in recent years.
BPA has not resolved problems associated with its open-ended obligation
to be the net provider of wholesale electricity in the region--the
major cause of its recent cost increases. While BPA has issued a draft
strategic plan that includes an objective of clarifying how much power
it will provide to its customers, and at what price, starting in fiscal
year 2007, this plan lacks specificity. According to its plan, BPA will
contractually set the amount of power each customer is able to buy at
BPA's lowest cost-based rate. BPA's plan also states that BPA will
consider using incremental rates[Footnote 3] to define pricing and
terms for supply beyond this amount of power. However, BPA's plan does
not specify the amount of power BPA will allow its customers to buy at
its lowest rate nor the specific manner in which incremental rates will
be charged. If the amount of power sold to customers at its lowest rate
exceeds the firm output of the federal power system--the amount of
power that can be generated during a critical water year--BPA could
still need to purchase power from other sources to meet its commitments
during low water years. Further, if the incremental rates do not fully
reflect BPA's costs of acquiring any additional power it sells, BPA's
customers will not have appropriate incentives to conserve or seek
alternative sources of power. Finally, whether BPA's strategic plan
will ultimately be implemented remains unclear. BPA has not carried out
similar proposals made in the past--such as in the late 1990s, when a
four-state panel recommended that BPA limit its commitments to the firm
output of the federal power system and charge incremental rates to
cover its cost of acquiring any additional power. BPA officials said
that BPA ultimately declined to implement such an approach under strong
regional pressure from its customers to provide more power.
Regarding other costs, BPA has taken steps to reduce costs or control
the extent of future cost increases in the areas of power generation,
fish and wildlife programs, and internal operations. For example, BPA
has reduced funding in general areas such as travel, training,
supplies, and staffing, as compared with 2001 funding levels. In
addition, BPA has taken steps to centralize its risk management process
to better control its costs. Among other things, BPA has established a
management plan outlining a new approach to risk management and has
hired a Chief Risk Officer. However, BPA's plan to date generally does
not identify specific activities, resources, and time frames for
completing implementation of its new approach; and this lack of
specificity prevented us from reviewing the plan's progress in a
meaningful way.
We are making four recommendations to BPA to ensure that the agency can
control costs of future power purchases and that it clarifies key
elements of the implementation of its new risk management process.
Specifically, we are recommending that BPA reduce its future risk of
being overcommitted by (1) defining rights to purchase the firm output
of the federal power system so that the amount of power that BPA sells
at its lowest, cost-based rate is equivalent to the firm output of the
existing federal power system, (2) charging incremental rates for any
power sold beyond this amount that reflect BPA's cost of acquiring that
power, and (3) studying the feasibility of issuing a rule under the
Administrative Procedure Act to define the rights to purchase power and
the terms of incremental rates. We are also recommending that BPA
identify specific activities, resources, and time frames for
implementing its risk management initiatives. In commenting on a draft
of this report, BPA generally agreed with our findings and
recommendations.
Background:
Although BPA is a self-funded agency, it has ongoing authority to
borrow from Treasury to fund capital expenditures and is repaying funds
appropriated in the past to finance the construction of dams and
generating and transmission facilities. According to the Northwest
Power Act, BPA's revenues from selling power and transmission services
must cover its costs, which include repayment of its debt, interest,
operating and maintenance costs, and the cost of any power purchased
for resale to meet its customers' needs, among other things. BPA's
current 5-year rates include the ability to adjust rates in response to
changing cost and revenue conditions.
BPA's customers include public utilities in the Pacific Northwest, as
well as a few aluminum companies and other large industrial customers,
known as direct service industries. BPA also provides power to some
investor-owned utilities in the Pacific Northwest. In addition, BPA
sells or exchanges power with utilities and power marketers in Canada
and the western United States. Preference--the opportunity to obtain
first access to BPA power--is defined by statute and gives priority to
public utilities and other public entities to ensure that the federal
hydropower projects are operated for the benefit of the general public,
particularly residential and rural customers. However, BPA's nonpublic
customers in the Pacific Northwest have priority in access to BPA power
over public utilities in other parts of the country.
BPA sells power to its customers through two mechanisms. First, BPA
sells power through long-term contracts at cost-based rates that are
established in periodic rate cases, which have recently taken place
every 5 years. The Federal Energy Regulatory Commission (FERC)--
pursuant to the Northwest Power Act--approves BPA's rates after
determining that the rates BPA proposes for its firm power are
sufficient to cover BPA's costs. Second, BPA often sells secondary
power, defined as power produced beyond the amount that BPA has
committed to sell to its customers at its cost-based rates. These
secondary sales are often transacted at market-based prices.[Footnote
4] The time frames of these secondary sales range from hourly to as
much as 18 months in advance.
The amount of power produced by the federal power system is highly
variable, largely depending on prevailing water conditions. For
example, according to BPA, in the last 10 fiscal years, the annual
runoff of the Columbia River at The Dalles Dam has varied from a low of
about 79 million acre-feet in fiscal year 2001 to a high of about 194
million acre-feet in fiscal year 1997; and the amount of power
generated by the federal power system has varied from a low of about
7,300 average megawatts (aMW) to a high of nearly 12,000 aMW.[Footnote
5] Since BPA's revenues from secondary sales depend on the amount of
power produced by the federal power system, these revenues are also
highly variable. Because of this inherent uncertainty about how much
power BPA will have to sell in any given year, BPA officials estimate
for planning purposes that the firm output of the federal power system
is about 8,000 aMW.
To promote competition in wholesale electricity markets, the federal
government took several actions in the 1990s that affect BPA's
operations. For example, in 1992, the Congress passed the Energy Policy
Act, authorizing FERC to require utilities, on a case-by-case basis, to
allow competitors to use their transmission lines for wholesale sales
of electricity. In 1996, FERC ordered that electric transmission
systems be opened to all qualified wholesale buyers and sellers of
electricity. FERC also required utilities to separate operations and
management of their generation and transmission businesses to prevent
discriminatory practices, such as denying competitors equal access to
transmission lines. While BPA's transmission system is outside of
FERC's jurisdiction, BPA voluntarily complied with key features of
FERC's orders. For example, in 1997, BPA split its operations into a
Power Business Line and Transmission Business Line. BPA took other
actions to attempt to position itself in the more competitive market
that was emerging in the 1990s. For example, in its 1995 Business Plan,
BPA announced its intent to expand its position in the wholesale
electricity market. Responding to the increased choices and falling
prices that were available to its customers, BPA planned to increase
its long-term revenue by entering new markets with new product lines.
Specifically, the Business Plan proposed an Energy Services Business
Line to provide planning and analytic services to customers and
advocated increased spot-market power purchases to provide it resource
flexibility in a time of shifting demands and increasing obligations to
migrating salmon.
In the mid-1990s, wholesale power prices dropped in the Pacific
Northwest, and power marketers began to offer wholesale power prices
lower than the prices BPA charged its customers. BPA's customers
responded by reducing their purchases of BPA power by about 1,800 aMW-
-a reduction in demand of almost 25 percent. Because of this drop in
demand from its customers, BPA became concerned that it would not be
able to sell its power at prices high enough to cover its costs. In
response to concerns about BPA's competitiveness and to establish
regional consensus on BPA's role in a competitive wholesale
marketplace, the governors of Idaho, Montana, Oregon, and Washington
convened a committee in 1996 representing BPA and its major customer
and stakeholder groups. The committee issued a report--known as the
Comprehensive Review of the Northwest Energy System--recommending that
BPA return to its historic role of marketing power from the federal
power system, rather than becoming an aggressive marketer of products
and services in the emerging competitive power market.[Footnote 6]
Accordingly, the Comprehensive Review report recommended that BPA avoid
acquiring resources to meet load growth, except on a direct bilateral
basis where the customer takes on the risk, and that BPA manage and
control its costs to remain competitive.
After the low prices of the mid-1990s, Pacific Northwest electricity
prices became more volatile. Trends in Pacific Northwest wholesale
electricity prices are shown in figure 1. Average monthly wholesale
electricity prices increased somewhat in 1998 and 1999, as demand in
the region grew while little new generation capacity was added. In mid-
2000, electricity prices in California skyrocketed due in part to low
water conditions that reduced the total supply. Because hydroelectric
power provides such a large part of the total power supply in the
region, low water years tend to cause high prices due to the consequent
reduction in the total supply of power. Because California's
electricity market is integrated with the rest of the western region,
prices in the Pacific Northwest quickly followed California's lead and
rose to unprecedented levels. Average wholesale prices in the Pacific
Northwest remained high until the summer of 2001. Since then, prices
have returned to levels similar to those seen in the late 1990s.
Figure 1: Average Monthly Prices for Wholesale Electricity in the
Pacific Northwest, 1997-2003:
[See PDF for image]
Note: Wholesale electricity prices are expressed in dollars per
megawatt-hour (MWh) and are not adjusted for inflation. These prices
are from the Mid-Columbia Hub and are representative of wholesale
electricity prices in the Pacific Northwest.
[End of figure]
Inherent Advantages Help BPA to Provide Low-Priced Power, but Its Open-
ended Obligations Are a Competitive Disadvantage:
BPA has inherent advantages, including its access to power from the
federal power system, that have generally enabled it to provide power
to customers in the Pacific Northwest at prices lower than other
sellers of wholesale power. However, unlike other sellers of wholesale
power, BPA has open-ended obligations to provide power and other
benefits to its customers and others in the Pacific Northwest that have
increased BPA's costs. In addition, the multiple-use nature of the dams
in the federal power system constrains the amount of power that BPA has
available to sell. These open-ended obligations and constraints have
increased pressure on BPA over time, engendering disputes in the region
over the allocation of the limited resources of the federal power
system, and contributing to increases in BPA's costs relative to the
costs of competing sources of electricity.
BPA's Access to Hydroelectric Power and Federal Financing Offer
Competitive Advantages:
BPA's most important cost advantage is that power from the federal
power system is primarily produced at hydroelectric dams, which overall
have low costs. According to BPA data, hydroelectric generation has
accounted for more than 90 percent, on average, of the generation
output of the federal power system over the past 2 decades. Many of
these hydroelectric facilities were built decades ago and had
relatively low construction costs compared with newer generating
facilities. In addition, these hydroelectric facilities tend to have
lower operating costs than other sources of electricity that consume
costly fossil or other fuels. As a result of these advantages,
hydroelectric power plants in the Pacific Northwest typically produce
power for less than $5 per MWh (as shown in fig. 2), compared with the
region's coal and nuclear plants, which produce power for between $15
to 20 per MWh, or combined cycle turbine facilities that burn natural
gas or oil, which produce power for more than $20 per MWh.
Figure 2: Average Production Costs for Different Types of Generating
Plants in Idaho, Oregon, Washington, and Western Montana, 1996-2002:
[See PDF for image]
Note: In inflation-adjusted dollars, base year 2003. Production costs
are measured in dollars per MWh and reflect data for the North American
Electric Reliability Council's Northwest Power Pool subregion.
Production costs reflect variable and fixed costs associated with a
generating plant. Source dataset does not have a value for nuclear
generation in 2002. Combined cycle turbine generators use natural gas
or oil.
[End of figure]
BPA also enjoys advantages related to financing due to its status as a
federal agency. BPA has access to federally financed debt, which
generally offers lower interest rates than those available to private-
sector entities. BPA's federal financing is divided into two
categories--appropriated debt and Treasury debt. Appropriated
debt[Footnote 7] consists of appropriations received by BPA and the
generating agencies to construct the generating and transmission
projects from which BPA markets power. As of September 30, 2003, the
outstanding balance of BPA's appropriated debt was about $4.7 billion.
As a result of legislation passed in 1996, BPA's appropriated debt was
restructured in 1997 to increase the interest rates to bring them in
line with the prevailing Treasury rates. However, the principal on this
debt was adjusted downward so that, except for the interest on the $100
million that BPA paid as part of the restructuring, the annual interest
BPA pays on the debt remains the same.[Footnote 8]
In addition to its appropriated debt, BPA has authority to borrow from
the Treasury on an ongoing basis. BPA's Treasury borrowing stems from
authority granted in the Federal Columbia River Transmission System Act
of 1974, as amended, which allows BPA to have up to $4.45 billion in
Treasury debt outstanding at any one time. The $4.45 billion consists
of two separate borrowing limits: $1.25 billion is reserved for
conservation and renewable resource loans and grants, and $3.2 billion
for transmission and other capital investments. This debt is issued at
market interest rates that are comparable to other government agency
obligations, and these rates are higher than Treasury rates. As of
September 30, 2003, BPA had about $2.7 billion of debt held by the
Treasury. As BPA pays off debt, it has greater funds available for
future borrowing.
BPA's status as a federal agency also has conferred advantages in
securing financing from the private sector. BPA does not have authority
to borrow directly from nonfederal sources, but BPA has secured private
sector financing by taking responsibility for the debt of other
entities. For example, BPA is responsible for the debt service of bonds
issued by Energy Northwest, a consortium of public utilities, to build
three nuclear plants, only one of which is currently operating. While
the federal government explicitly does not guarantee Energy Northwest
bonds, Moody's Investors Service views them as having an implicit
federal guarantee. In addition, Moody's Investors Service and Fitch
Ratings give credit strength to BPA's ties to the federal government.
Thus, the interest that BPA pays on Energy Northwest bonds is lower
than would be paid without BPA's ties to the federal government.
As a result of BPA's inherent cost advantages, it generally has been
able to sell electricity at lower wholesale prices than other major
investor-owned utilities in the Pacific Northwest, as shown in figure
3.
Figure 3: Average Wholesale Prices for Electricity Sold by BPA and the
Five Largest Investor-Owned Utilities in the Pacific Northwest, 1996-
2002[A]:
[See PDF for image]
Note: Prices are given in inflation-adjusted dollars, base year 2003.
[A] Average wholesale prices are expressed in cents per kilowatt-hour,
where a kilowatt-hour is equal to one thousand watt-hours. Average
wholesale prices are calculated by dividing a utility's total revenue
from power sales by the total amount of power it sold. The resulting
weighted average may not represent the actual price paid by any
particular customer, but it reflects the average annual prices paid by
customers as a group.
[End of figure]
BPA's advantages contribute significantly to the relatively low retail
price of electricity sold in the Pacific Northwest. Because BPA sells
about 45 percent of all the electricity used in the Pacific Northwest,
its wholesale prices play a large role in determining the average
retail price of electricity throughout the Pacific Northwest. As shown
in figure 4, the average retail price of electricity (as expressed in
average revenue per kilowatthour) in states in the Pacific Northwest is
generally lower than electricity sold in much of the rest of the United
States. While the nationwide average retail price of electricity from
1996 to 2002 was 7.41 cents per kilowatthour, Washington state's
average price of electricity over this period was 4.81 cents per
kilowatthour, Oregon's was 5.46 cents per kilowatthour, Idaho's was
4.63 cents per kilowatthour, and Montana's was 5.61 cents per
kilowatthour.[Footnote 9]
Figure 4: Average Retail Prices of Electricity, 1996-2002:
[See PDF for image]
Note: Prices are given in inflation-adjusted dollars, base year 2003,
and have been rounded to hundredths of a cent per kilowatt-hour.
Average retail prices are expressed in cents per kilowatt-hour,
calculated by dividing total revenue from power sales by the total
amount of power sold in a state. The resulting weighted average may not
represent the actual price paid by any particular customer, but
reflects the average annual prices paid by customers as a group.
[End of figure]
BPA Has Competitive Disadvantages That Increase Its Costs:
BPA also has competitive disadvantages--stemming mainly from statutory
obligations--that increase its costs relative to other sellers of
wholesale power. Most importantly, unlike other power marketing
administrations, BPA has a legislative mandate under the Northwest
Power Act to be the "net provider" of wholesale electricity in the
region--i.e., BPA must meet the power needs of all utilities in the
region to the extent that the utilities' own generating resources are
insufficient to meet the demand of their retail customers. If a utility
requests power from BPA, BPA must provide this power regardless of
whether its own generating resources are sufficient to meet the demand.
Past attempts by BPA to meet growing regional demand have led to
significant cost increases that BPA has had to cover in its power
rates. For example, in the early 1970s, BPA entered into financing
agreements with Energy Northwest to acquire the generating capability
of three nonfederal nuclear power plants.[Footnote 10] Later, a variety
of events, including construction cost overruns and lower-than-
estimated power demand growth, made it clear that some of these plants
would not be economical to complete or operate. Accordingly,
construction was halted on two of these plants. As a result, BPA is
currently responsible for about $3.8 billion in nonfederal debt
associated with two nonoperating nuclear plants, along with $2.2
billion in nonfederal debt for the one operating nuclear plant, the
Columbia Generating Station. Servicing the debt related to the
nonoperating plants that don't generate any revenue to help offset this
cost has raised BPA's average costs significantly, requiring BPA to
charge more for its power sales. In 1994, BPA again tried to expand the
capacity of the federal power system by entering into a financing
agreement to acquire the capacity of a proposed nonfederal gas-fired
power plant for a 20-year period. Later, as wholesale market prices for
power fell, some of BPA's customers reduced their demand for BPA power,
and BPA found that it did not need the power from the gas-fired plant.
BPA then breached its contract, which cost the agency over $280 million
in net settlement payments.
Under the requirements of the Northwest Power Act, BPA also provides
financial payments to some of its customers in lieu of providing power
through a program called "residential exchange." The residential
exchange program is designed to share the benefits of low-cost power
from the federal power system with residential and small-farm customers
of investor-owned utilities.[Footnote 11] Because investor-owned
utilities in the Pacific Northwest have typically had higher costs than
the region's public utilities, the residential exchange program
attempts to compensate for the difference and reduce the prices paid by
the investor-owned utilities' retail customers by making financial
payments to the investor-owned utilities. The size of these payments is
determined by comparing an investor-owned utility's average cost of
producing power to the rates BPA charges its public utility customers,
with BPA making up the difference. Between fiscal years 1982 and 2003,
BPA's financial records show that the annual cost of the program has
averaged about $210 million.[Footnote 12]
The Northwest Power Act also requires BPA--along with the other federal
agencies responsible for managing, operating, or regulating
hydroelectric facilities in the Columbia River Basin--"to protect,
mitigate, and enhance fish and wildlife" resources impacted by the
development and operation of those facilities. Under the Act, BPA is
required to implement and fund measures supporting fish and wildlife in
a manner consistent with the program developed by the Northwest Power
and Conservation Council--a regional agency established by the
Northwest Power Act to balance the Northwest's environment and energy
needs, including developing a program to protect and rebuild fish and
wildlife populations affected by hydropower development in the Columbia
River Basin. BPA must also implement and fund actions contained in the
biological opinions directed at avoiding jeopardy to and recovering the
14 Columbia River Basin fish populations listed as threatened or
endangered under the Endangered Species Act. Because BPA is the primary
source of funding for the Northwest Power and Conservation Council's
program and for the implementation of the actions contained in the
biological opinions, BPA's costs are impacted by the costs of
protecting fish and wildlife to a greater degree than some of its
competitors. BPA financial records show that between fiscal years 1985
and 2003, BPA's costs to implement these actions have increased on an
annual basis, from about $85 million in 1985 to about $256 million in
2003, in 2003 dollars. BPA's total spending on these programs during
the same period was over $3.3 billion. (For more detailed information
on the growth in BPA's program spending on fish and wildlife from 1985
through 2003, see app. II.):
In addition, the multiple-use nature of the dams in the federal power
system can reduce the amount of power that BPA has available to sell,
which increases BPA's average costs of providing power. In addition to
generating power, the dams of the federal power system are also
operated for the protection of fish and wildlife, flood control,
irrigation, navigation, and recreational benefits. These other uses
change the timing and amount of the water flow, which in turn can
reduce the total amount of power that the federal power system
produces--and therefore, the amount of power that BPA has to market.
For example, to fulfill the obligations of the Northwest Power Act and
the Endangered Species Act, water is released from storage reservoirs
in the Columbia River Basin to aid migrating salmon and steelhead,
including many threatened or endangered fish populations. Water
releases for fish migration can generate power, but such releases
typically occur during springtime when water flows are already high
and, consequently, power prices are low. As a result of these releases,
less water is retained behind the dams to be released later to generate
power when prices are higher. In addition, water is sometimes spilled
without generating electricity to aid fish migration instead of being
sent through the dams' turbines to generate power. As a result of these
constraints on power production at the federal dams, BPA must at times
purchase power to meet its contractual obligations; and at other times,
BPA's revenues from secondary sales are reduced. Purchasing additional
power and having less power to sell combine to increase BPA's average
costs--defined as BPA's total costs divided by the total power
generation that BPA sells. According to BPA estimates for fiscal years
1985 through 2003, water releases for fish and wildlife purposes have
cost BPA almost $4 billion in power purchases to meet contractual
obligations and in foregone revenues.[Footnote 13] Diverting water for
irrigation purposes has a similar effect on BPA's revenues and average
costs. BPA estimates that foregone revenues attributed to irrigation
withdrawals are currently about $180 million per year.[Footnote 14]
As population and economic activity in the Pacific Northwest region
have grown, the demand for power from the federal power system has
increased. While in the past BPA typically provided power to public
utilities and had power left over for some large industrial customers,
demand from public utilities has grown so that, according to BPA
officials, this demand is currently about equal to the entire firm
output of the federal power system. Demand from investor-owned
utilities has also grown, and consequently, the number of these
utilities' customers who are entitled to financial benefits through the
residential exchange program has increased. In addition, the demands on
the operation of dams for other uses--particularly for fish and
wildlife programs--have increased. These increasing and often competing
demands for the resources of the federal power system have led to
disputes among the beneficiaries over how these resources are
distributed. For example, the method by which BPA calculates
residential exchange payments has spurred disputes within the region.
Investor-owned utilities and state regulators have argued that BPA has
manipulated the method to reduce payments below appropriate levels.
Conversely, public utilities have argued that payments to investor-
owned utilities have been too high and that BPA has inaccurately
applied a statutory provision designed to protect public utilities from
increased prices. Some public utilities recently filed a lawsuit
against BPA, claiming that a settlement agreement BPA signed with
investor-owned utilities inappropriately increased program costs.
BPA's costs--as reflected in its cost-based power rates--more than
doubled in the 30 years between fiscal years 1972 through 2001, when
adjusted for inflation, and increased by a factor of about 7 in nominal
terms (not adjusted for inflation).[Footnote 15] Figure 5 shows BPA's
rates from 1972 through 2001 both in dollars adjusted for inflation and
in nominal dollars (not adjusted for inflation).[Footnote 16] During
this period, BPA's backing of the construction of the nuclear plants
and the gas-fired plant, discussed previously in this report,
contributed to the agency's cost increases as reflected in its rising
rates.
Figure 5: BPA's Average Power Rates, Fiscal Year 1972-2001:
[See PDF for image]
Note: Data are for BPA's historical average priority firm power rates.
Nominal prices refer to BPA's rates that have not been adjusted for
inflation. Real prices refer to BPA's rates that have been adjusted for
inflation with fiscal year 2003 as the base year.
[End of figure]
Since the late 1970s, while BPA's rates increased significantly, the
cost of new sources of power generation decreased as the efficiency of
new technologies improved. For example, in its 1995 Business Plan, BPA
reported that a number of factors, including "falling fuel prices and
the emergence of new and aggressive competition" had led to a situation
where for the first time in BPA's history, BPA's rates were as high as
the costs of alternative sources of electric power. As a result, as
discussed previously in this report, some of BPA's customers began to
reduce their demand for BPA power in favor of these cheaper sources of
power. BPA has more recently reported that since the West Coast energy
crisis of 2000 and 2001, and with recent increases in natural gas
prices, the costs of new power plants are again higher than BPA's
rates. However, after 1995, BPA stopped regularly tracking and
reporting consistent data on the cost of the least expensive
alternative form of power generation, so we were unable to compare the
agency's rates relative to the cost of such alternatives after that
year.
BPA's Open-ended Obligation to Provide Power and Other Factors Led to
Large Cost Increases for BPA:
BPA's open-ended obligation to be the net provider of wholesale power
to the region is the major cause of its recent cost increases. This
obligation led the agency to overcommit to provide power to its
customers in the current rate period--from fiscal years 2002 to 2006.
BPA's costs rose dramatically as the agency purchased large amounts of
power, at average prices much higher than the costs of power from the
federal power system, and took other steps to meet its obligations.
BPA's rate structure, which did not charge incremental rates equal to
BPA's costs of acquiring additional power, contributed to the rising
costs because it did not give customers adequate incentives to conserve
or seek power from alternative sources. Drought conditions and other
factors have also caused BPA's costs associated with its power
marketing business to increase in recent years.
Open-ended Obligation to Provide Power and BPA's Rate Structure Led to
Large Cost Increases for BPA:
BPA experienced a demand increase of more than 50 percent from its
public utility customers in the current rate period, which began in
fiscal year 2002. Figure 6 shows the amount of power that BPA's three
main customer groups purchased from fiscal years 1993 to 2001 and the
amount of power these same groups signed contracts to purchase during
the current rate period. Demand from the public utilities increased
from an average of approximately 4,300 aMW during the fiscal year 1997
to 2001 rate period to an average of approximately 6,800 aMW during the
current rate period. As described earlier, the Northwest Power Act
requires BPA to serve the net requirements of public utilities if these
utilities request power, regardless of whether BPA's own generating
resources are sufficient to meet this demand. Therefore, BPA was
required to serve this increased demand.
Figure 6: Power Purchased and Power Contracts Signed by BPA's Major
Customer Groups, Fiscal Year 1993-2006:
[See PDF for image]
[End of figure]
In addition to signing contracts to provide more power to its public
utility customers, BPA also signed contracts to provide power to
customers that it was not statutorily required to serve during the
current rate period. For example, BPA agreed to provide approximately
1,500 aMW of power to the direct service industries during the fiscal
year 2002 to 2006 rate period, despite the fact that BPA's statutory
mandate to serve the direct service industries ended at the end of
fiscal year 2001. BPA officials told us that the decision to serve the
direct service industries was made at the request of the then Secretary
of Energy and that BPA management also felt it was the correct thing to
do, given BPA's previous requirement to provide power to these
customers. BPA also agreed to provide 1,000 aMW of power to the
investor-owned utilities as part of a settlement agreement--previously,
BPA had only provided financial payments to investor-owned utilities as
part of the residential exchange program.
The substantial increase in customer demand that occurred at the
beginning of fiscal year 2002 coincided with the expiration of the 20-
year power sales contracts that BPA signed with the majority of its
customers after the passage of the Northwest Power Act. To allow
customers to sign new long-term contracts for firm power, BPA
established a "subscription window"--from April to October 2000. During
this subscription process, the majority of BPA's customers signed 10-
year contracts for fiscal years 2002 through 2011.
Figure 7 shows a time line of BPA's major actions during its
subscription and ratemaking processes against a backdrop of wholesale
electricity prices in the Pacific Northwest. When BPA began planning
for the subscription process in early 1997, customers had recently
reduced their power purchases from BPA by approximately 1,800 aMW to
take advantage of low wholesale market prices. BPA officials told us
that, due to the reduction in customer demand, they were concerned
about the possibility that they might not be able to sell enough power
to cover their costs. In BPA's December 1998 record of decision on the
subscription process, BPA stated that two of its principal goals were
to spread the benefits of the federal power system as broadly as
possible and avoid rate increases. Toward that end, BPA committed
itself to providing power to investor-owned utilities and direct
service industries, as well as serving all public utility demand placed
on it.
Figure 7: Major Events and Electricity Prices during BPA's Subscription
and Ratemaking Processes:
[See PDF for image]
Note: Wholesale electricity prices are expressed in dollars per MWh and
are not adjusted for inflation. These prices are from the Mid-Columbia
Hub and are representative of wholesale electricity prices in the
Pacific Northwest.
[End of figure]
BPA officials told us that when wholesale electricity prices rose
slightly during the late 1990s, they became concerned about customers
demanding more power than BPA could provide from the federal power
system. In May 2000, at the beginning of the subscription window, BPA
filed a rate case with FERC to set power rates for fiscal years 2002
through 2006. In the rate case, BPA estimated that it would be called
on to serve approximately 1,700 aMW of power beyond the firm output of
the federal power system, based on input from customers on their
expected power demand.
In June 2000, immediately after BPA filed its rates for 2002 through
2006 with FERC, wholesale power prices increased to levels never before
seen in the Pacific Northwest, and BPA's public utility customers
turned to BPA to avoid the high market prices. By the end of the
subscription process, BPA's public utility customers had requested
1,600 aMW more power than BPA anticipated in its May 2000 rate case. In
total, BPA's customers signed subscription contracts for 3,300 aMW of
power (roughly equivalent to three times the power used by the city of
Seattle) beyond the firm output of the federal power system.
BPA's rate structure for the fiscal year 2002 to 2006 rate period
contributed to the increase in demand for BPA power. According to BPA
officials, BPA planned to meet customer demand for power by purchasing
additional power from other sources in contracts of varying durations.
In its May 2000 rate case, BPA decided to sell all of its power at a
single rate, which averaged the cost of the purchased power with the
lower cost of power produced by the federal power system. This averaged
rate spread the costs of serving the additional demand over all of
BPA's customers and, as a result, did not distinguish between the price
of low-cost power from the federal power system and the higher cost of
power from other sources. In addition, the averaged rate structure gave
customers poor incentives to seek alternative power sources during the
subscription process, because customers were not exposed to the
incremental cost of acquiring additional power on the market. While BPA
considered the possibility of charging differentiated rates prior to
its May 2000 rate case, it ultimately declined to do so.
To meet the substantial increase in customer demand, BPA spent about
$900 million in fiscal year 2002 and about $760 million in fiscal year
2003 on power purchases and payments to customers to reduce their
demand. These costs comprised approximately 25 percent of BPA's total
costs in each year. Due to large increases in the wholesale price of
power, the power that BPA purchased from other sources to meet the
substantial increase in customer demand generally cost much more than
power generated by the federal power system. For example, BPA's average
cost for the power it purchased for 2002 and 2003 is approximately $37
per MWh, while the average price of BPA's power, as established in its
May 2000 rate case, was about $22 per MWh. When purchasing power from
the wholesale market became extremely expensive, BPA reduced its power
purchases and instead paid its customers to reduce their demand for BPA
power, in transactions referred to as "buy-backs." BPA's costs
associated with buy-backs were about $450 million in fiscal year 2002
and about $370 million in fiscal year 2003. The majority of the buy-
back payments went to investor-owned utilities and direct service
industries. BPA was eventually forced to raise its rates by more than
40 percent for the majority of BPA's customers to recover its costs and
ensure that it had the funds to meet its payments on Treasury debt.
Drought Conditions and Other Factors Have Also Led to Cost Increases
for BPA:
While BPA's overcommitment to provide power is the major cause of its
cost increases in 2002 and 2003, other factors have also contributed to
its cost increases in recent years. In 2001, severe drought conditions
reduced the amount of power produced by the federal power system.
According to BPA data, the annual runoff volume in the Columbia River
Basin in 2001 was 40 percent below average and the second lowest since
fiscal year 1929. To meet its customers' demand for power, BPA spent
about $2.2 billion on power purchases in fiscal year 2001, an increase
of $1.9 billion over average annual expenditures on power purchases in
fiscal years 1997 through 2000.
In addition, some of BPA's other costs associated with marketing power
have increased in recent years for a variety of reasons. These costs
are associated with power generation (including costs for the
residential exchange program), the fish and wildlife program, and BPA's
internal operations. (For a more detailed presentation of BPA's costs
associated with its power marketing business from fiscal year 1997 to
2003, refer to app. III.):
BPA's power generation costs have increased consistently since 2000
because of increases in the cost of maintaining and operating the
federal power system, as well as increases in payments to investor-
owned utilities under the terms of a settlement agreement. BPA has
reported that the increased costs for the federal power system were
needed to make up for past under-investment. For example, a
benchmarking study conducted in 2000 demonstrated that the federal
hydropower system had not been maintained at the same level as
comparable facilities and that increased investment was needed to
improve its reliability, capacity, and safety. In addition, under the
terms of a settlement agreement related to the residential exchange
program, BPA's payments to investor-owned utilities increased in 2002
and 2003 by about $59 million per year, on average, compared with 1997
to 2001.[Footnote 17] This increase is due to a change in how BPA
calculates payments to these utilities.
BPA's average annual fish and wildlife program costs for 2002 and 2003
are 33 percent higher ($42 million) than they were from 1997 to 2001,
adjusting for inflation. According to BPA officials, the increase is
due primarily to requirements to protect fish species listed under the
Endangered Species Act. These requirements include measures designed to
improve fish passage at the dams, analyze and refine hatchery
management practices, study and report on ocean conditions, and improve
spawning and rearing habitat. Fish and wildlife costs also increased
because additional staff were needed to handle the contracting and
administrative workload associated with threatened and endangered
species recovery actions. BPA's fish and wildlife program staff
increased from 35 in 1997 to 63 by 2003.
Finally, BPA's average annual internal operations costs associated with
its power marketing business for 2001 to 2003 are 34 percent higher (or
$32 million, adjusting for inflation) than they were from 1997 to 2000,
largely because of new requirements regarding employee retirement costs
and increased demand placed on BPA during the current rate
period.[Footnote 18] Beginning in 2001, BPA began to pay certain
retirement costs for its employees and some partner agency employees
that it previously was not required to pay.[Footnote 19] Between 2001
and 2003, these costs averaged almost $17 million, adjusting for
inflation, accounting for more than half the increase in internal
costs, as compared with 1997 to 2000 average cost levels. In addition,
according to BPA officials, a more complex rate structure created by
greater demand for BPA power and new contracts increased BPA's need for
staffing and support, which raised its staffing and support costs.
BPA Has Not Resolved Problems That Led to Its Recent Cost Increases,
but It Has Taken Steps to Control Other Costs:
BPA has not resolved problems associated with its open-ended obligation
to be the net provider of wholesale electricity in the region--the
major cause of its recent cost increases. BPA has issued a draft
strategic plan that includes an objective of clarifying its commitments
to sell power to its customers. BPA proposes to contractually define
the amount of power it will sell its customers at its lowest, cost-
based rates and is also considering charging incremental rates for any
power it sells beyond this amount. However, BPA has not clearly defined
how much power it will sell at its lowest cost-based rates or the way
it will implement incremental rates. It is also unclear whether BPA's
draft plan will be implemented. BPA had similar plans in the late 1990s
but did not implement them because of pressure from customers to
increase, rather than limit, the amount of demand BPA served. BPA has,
however, taken steps to reduce costs or control the extent of future
cost increases in the areas of power generation, fish and wildlife
programs, and internal operations. Further, BPA is improving its risk
management process in order to maintain better control over its costs.
However, regarding its risk management process, BPA's plan outlining
its new approach does not contain some key elements, including details
on specific activities, resources, and time frames.
BPA Has Not Resolved Problems That Led to Recent Cost Increases:
BPA has not established a final, formal policy on how it plans to
manage its open-ended obligation to be the net provider of wholesale
electricity in the region--the major cause of its recent cost
increases. In March 2004, BPA issued a draft strategic plan to define a
direction for the agency. As part of that plan, BPA established an
objective of clarifying how much power it will provide to its
customers, and at what price, starting in fiscal year 2007. BPA's plan
states that it will establish, via long-term power contracts with its
customers, the amount of power that customers are able to buy at a low
rate.[Footnote 20] If customers request power beyond this amount, BPA's
plan states that BPA will consider use of incremental rates to
distinguish between low-cost power from the federal power system and
power from higher-cost resources. According to BPA, establishing rights
to BPA's power and using incremental rates would send appropriate price
signals to its customers and would be consistent with broad customer
interest in allocating rights to power from the federal power system.
However, BPA's draft strategic plan does not provide key details on how
it plans to implement its approach to defining rights to purchase power
and using incremental rates. For example, BPA's plan does not specify
the amount of power that its customers would be able to buy at BPA's
lowest rates. If this amount exceeds the firm output of the federal
power system, then during low water years, BPA could still need to buy
power to meet its contractual obligations. In addition, BPA's plan does
not clarify how BPA's approach to incremental rates would be
implemented. As long as BPA's rates do not fully reflect its costs of
acquiring power to meet excess demand, then customers will not have
appropriate incentives to conserve or seek alternative power supplies.
In addition, it remains unclear whether BPA will succeed in making
these changes once they are more clearly defined. While BPA officials
told us that they have the discretion to implement BPA's plan, they
said that they would strongly prefer to have regional agreement before
making a final policy decision. Accordingly, BPA intends to hold a
series of public meetings with its customers and stakeholders in 2004
to discuss its proposals. According to BPA officials, once they have
received input and comments from all their customers and other
stakeholders, the BPA Administrator will make a final policy decision
and sign a record of decision in the fall of 2004. However, even if BPA
reaches regional agreement on its plan, BPA has not followed through on
similar proposals made in the past when faced with pressure from its
customers. As discussed previously in this report, in the mid-1990s,
BPA endorsed the recommendations of the Comprehensive Review report,
which represented the views of BPA and its major customer and
stakeholder groups. The report specifically recommended that BPA not
acquire additional resources to serve its customers' load growth,
except where the customers take on all the risk of the acquisition,
such as by paying incremental rates that cover BPA's full cost of
acquiring the additional power. However, under what BPA has
characterized as strong regional pressure from its customers, BPA
ultimately declined to implement such an approach in its 2000 rate
case.
The possibility remains that BPA will face similar pressures again,
although BPA officials identified several reasons why the agency is
less likely to need to purchase significant amounts of power in the
future, compared with recent years. For example, most of BPA's direct
service industry customers, such as aluminum smelters, are no longer in
operation, and some smelters are being dismantled. However, public
utility demand is currently about equal to the firm output of the
federal power system, according to BPA officials, and this demand is
expected to increase over time. Since public utilities have a statutory
right to purchase power from BPA, if future demand from public utility
customers exceeds the firm output of the federal power system, BPA may
again face pressure to average the cost of federal system power with
higher cost power from other sources.
In a recent report, the Northwest Power and Conservation Council
expressed concern that BPA's plan to allocate rights to power from the
federal power system and charge incremental rates, using policy
statements and records of decision, may not be sufficient to provide a
necessary level of policy durability, leaving open the possibility that
BPA could change its policy in the future[Footnote 21]. To improve the
durability of BPA's plan, the Council stated that BPA must clearly
identify the priority issues that are to be resolved, the process by
which they will be addressed, and adopt an aggressive schedule for
doing so. That schedule should result in offering new long-term
contracts by October of 2007. Further, while the Council decided not to
press for substantive rulemaking at this time, it noted that if BPA's
current approach proves incapable of resolving issues within that time
frame, alternative processes should be considered, including issuing a
rule under the Administrative Procedure Act to establish a policy on
allocating rights to power from the existing federal power system and
charging incremental rates. If adopted, this policy would be
implemented through subsequent contract and ratemaking procedures.
Unlike a record of decision, a policy adopted through a rulemaking
procedure would have the force of law, bind future BPA and customer
actions, and could not be altered unless BPA conducted a similar
process. Such measures would increase assurance that BPA would not
change direction in the future because of customer pressure.
BPA Is Taking Actions to Reduce and Control Costs in Other Areas:
BPA has recently taken a number of actions to reduce costs or to
control the extent of future cost increases in the areas of power
generation, fish and wildlife programs, and internal operations. When
setting its current rates, BPA estimated that the average costs of its
generating partners (the Army Corps of Engineers, Bureau of
Reclamation, and Energy Northwest) for the 2002 to 2006 rate period
would be $24 million less per year than from 1997 through 2001. BPA
officials based this estimate primarily on a 1998 review of BPA's costs
that projected (1) savings by increasing coordination of and investment
in the federal hydropower system and (2) operation and maintenance cost
reductions and increased revenues from the nuclear power plant. While
BPA and its partner agencies developed a strategy for jointly operating
the federal power system with the goal of reducing system
costs,[Footnote 22] BPA has acknowledged that it did not develop
adequate cost management plans to achieve the projected reductions and
that BPA's partner agencies never committed to the reductions. For
example, Corps officials stated that they had previously underinvested
in maintenance and needed to increase expenses to improve the
reliability, capacity, and safety of the hydroelectric facilities. BPA
officials agree that increased investment in the power system is
warranted but said that BPA is working with the partner agencies to
minimize these cost increases. For instance, BPA has worked with Energy
Northwest to defer maintenance and alter the fuel replacement schedule
to reduce costs for the nuclear plant. In all, BPA has reduced the
projected increase in the average annual costs of its generating
partners by $36.4 million for 2003 through 2006.
BPA has also taken several actions to control its costs associated with
the fish and wildlife direct program and reduce their uncertainty. The
direct program includes costs associated with (1) noncapital
expenditures for measures funded in support of the Endangered Species
Act and the Northwest Power and Conservation Council's fish and
wildlife program, (2) off-site capital projects (i.e., capital costs
not associated with a federal power system facility), and (3) a portion
of BPA's internal costs associated with its fish and wildlife related
support activities. In light of its financial problems, BPA directed
the Northwest Power and Conservation Council to ensure that actual
expenses for the direct program did not exceed $139 million annually
for fiscal years 2002 and 2003.[Footnote 23] In addition, BPA has taken
other measures to control direct program costs, including placing a
temporary hold on funding for land purchases and easements while BPA
reviewed its financial and liquidity position. While BPA's actions have
achieved its desired result of holding direct program expenses in
fiscal year 2003 to approximately $139 million, they have also
generated controversy among some stakeholders. For example, some
stakeholders maintain that BPA cut funding for the direct program when
it decided not to carry over more than $38.8 million that remained when
an earlier funding agreement for the direct program expired in 2001.
According to BPA officials, this decision was made in 1996, as the
funding agreement was being negotiated, and should not be considered
part of their recent efforts to control costs. In addition, some
stakeholders stated that BPA had cut another $17.4 million from its
direct program budget when it changed its planning and budgeting
methods for fish and wildlife programs in November 2002. This change
meant that because some costs incurred for projects in 2002 and prior
years were not identified and paid by a certain date, they had to be
paid from the 2003 and 2004 budgets, thereby reducing the amount of
funding available for new projects by an estimated $17.4 million in
those years. According to BPA officials, BPA changed its fish and
wildlife planning and budgeting methods to align them with the
budgeting and planning processes used in its other program areas.
Finally, to reduce internal operations costs, BPA initiated two
agencywide initiatives. As a first step, BPA reduced the fiscal year
2002 budget of each manager in its power marketing business and has
reduced funding in many general areas, such as travel, training,
supplies, staffing, research and development, and building upgrades.
For example, BPA reduced agency travel expenses by about half and
training expenses by about two-thirds from 2001 levels. According to
BPA officials, these steps have helped BPA reduce its internal
operations costs by $42 million from fiscal year 2002 to 2003. Second,
BPA is consolidating functions, such as procurement and information
technology, that were previously dispersed throughout the agency. In
addition, in March 2004, BPA contracted with a consulting firm to
perform a comprehensive overview of BPA's major functions, systems, and
processes to identify specific opportunities for program and
performance improvement, which may yield additional savings.
While some of these actions have led to decreased costs in certain
areas, BPA projects that its overall costs for the three categories in
fiscal years 2004 to 2006 will remain 27 percent higher than its
average from fiscal years 1997 to 2000. BPA officials said that without
the cost control measures, costs for these categories would be expected
to increase even more. They also noted that some of the cost increases-
-such as those required for fish and wildlife under the Endangered
Species Act--are largely beyond BPA's control.
BPA Is Taking Steps to Improve Its Risk Management Process and Better
Control Costs:
BPA recently concluded that its risk management process had not kept
pace with the changes taking place in the electricity industry and the
increasing demands being placed on it by its stakeholders, and that
this problem has contributed to BPA facing increased financial risk.
Specifically, in an April 2003 report to its customers and Northwest
citizens, BPA stated that, while it has historically assumed and
managed significant amounts of risk on behalf of its customers, BPA's
decision to take on demand beyond the firm output of the federal power
system has gone beyond the limits of risk that it can accept. As a
result, BPA is taking steps to improve its risk management process.
In June 2002, BPA hired a consulting firm to independently evaluate its
risk management process. Risk management includes risk assessment and
monitoring, which are two of the key elements of internal
control.[Footnote 24] Risk assessment identifies and analyzes the
relevant risks associated with achieving an organization's objectives,
while monitoring assesses the quality of performance of the risk
management process over time and identifies any departures from this
process. In its contract with the consultant, BPA asked the firm to:
* identify, evaluate, and rank BPA's enterprise-wide risks;
* assess the state of BPA's risk management;
* compare BPA's risk management approach and structure with the
industry's best and emerging practices;
* identify gaps in its risk management and control framework where
improvements may be appropriate; and:
* recommend an "Enterprise Risk Management" model and alternative
organizational structures.
The consultant found that although BPA had significant risk management
resources in specialized areas, based on BPA's business lines or
specific types of risk, the agency's risk management efforts were
decentralized and were not integrated into an enterprise-wide
structured approach.[Footnote 25] The consultant made numerous
recommendations for improvements in the following areas: planning and
preparedness; risk identification and prioritization; monitoring,
control, and reporting; follow-through and organizational learning; and
general organization and leadership.
In March 2003, BPA developed a management plan to implement some of the
consultant's key, high-level recommendations. The plan calls for two
main strategies. First, the plan calls for the establishment of a Chief
Risk Officer position and organization. According to the plan, the
Chief Risk Officer position is designed to elevate risk issues to the
senior management level on a par with business, financial, and program
strategies. The Chief Risk Officer would lead BPA's revamped risk
assessment and mitigation efforts and work across BPA's business lines
and program offices.
Second, BPA's plan calls for the establishment of two oversight
committees to operate under the direct, delegated authority of the BPA
administrator. The Enterprise Risk Management Committee would oversee
BPA's risk management program and would identify, analyze, evaluate,
treat, monitor, and communicate risks across BPA's business lines and
program offices. This committee is to consist of senior executives and
would facilitate integration of risks across BPA and ensure that risk
and strategy are considered in tandem. The committee would also
establish the acceptable zones or boundaries for risk, often referred
to as risk tolerances, within which the business lines will operate.
The second committee, called the Transacting Risk Management Committee,
would be headed by the Chief Risk Officer and handle the more tactical
and technical transacting risks within business lines. This committee
would focus on risks inherent in commodity market transactions and
counterparty credit exposures. It would also oversee policies and
procedures and establish risk monitoring and limits that will govern
the commodity transaction risks.
BPA has taken several significant actions to implement its management
plan. As of April 2004, BPA had made the following major changes to its
risk management process:
* centralized its risk management operations into a newly created Chief
Risk Office that is headed by a newly appointed Chief Risk Officer,
completed the initial transfer of risk-related jobs to the new Chief
Risk Office, and announced additional staff recruitment for the office
through the federal merit and competitive process;
* chartered and established the Transacting Risk Management Committee
and hired a staff manager for the Enterprise Risk Management Committee,
which has not yet been established; and:
* instituted a requirement for its power marketing business that
decisions in which the total lifetime costs, revenues, or potential
risks are estimated to exceed $500,000 will be formally documented in a
standard form BPA refers to as a "Decision Support Template."
While BPA continues its efforts to implement its plan and establish a
more centralized risk management process, work remains to be done to
ensure that the plan is successful. At this point, the plan provides
limited information on how BPA will complete its implementation of the
new approach to risk management. While the plan includes strategies and
high-level descriptions, it generally does not yet identify specific
activities, resources, and time frames for completing the
implementation of BPA's new approach. Neither does the plan address
when, and to what extent, BPA will address all of the consultant's
detailed recommendations. Without this type of information, it is
unclear when BPA intends to fully implement its new approach and to
what extent its approach will address the consultant's recommendations.
According to BPA, its management plan is not intended to provide the
full details necessary to implement its approach, and BPA intends to
monitor the implementation of the plan and perform an internal
assessment by September 2004. BPA officials told us that the Chief Risk
Officer will lead the effort to revise BPA's risk management process,
including responding to the consultant's detailed findings. However,
BPA was unable to provide documentation of the activities, resources,
and time frames it plans to take to fully implement its plan. Without
such documentation, it was not possible to review the plan's progress
in a meaningful way.
Conclusions:
Growing population in the Pacific Northwest region, combined with BPA's
open-ended obligation to provide power, have increased financial
pressures on BPA. Past BPA attempts to meet growing demand--by
providing financial backing for the construction of two nuclear power
plants that were never completed and one gas fired power plant, the
power from which BPA later determined it did not need--caused BPA's
costs to rise. This obligation to provide power was also the
fundamental cause of recent cost increases and financial difficulties.
Looking forward, this obligation remains a major source of risk for
BPA. BPA must control its costs or risk not being able to compete with
other power producers, potentially forcing it to default on its debt to
the Treasury. One way to avert this risk and resolve the problems
associated with BPA's open-ended obligation is to allocate (or define)
the rights to purchase the firm output of the existing federal power
system and use incremental rates to distinguish between this "low-cost"
power and any other power that BPA sells. While BPA currently plans to
contractually set the amount of power its customers can buy at its
lowest rate and to use incremental rates, similar intentions in the
recent past were not implemented, in part because of pressure from
BPA's customers to provide more power. It is therefore important for
BPA to credibly commit to allocating rights to purchase the firm output
of the federal power system and using incremental rates. To assist BPA
with its commitment to implement its draft strategic plan and increase
assurance that BPA will not change direction in the future, the
Northwest Power and Conservation Council has stated that a rule issued
under the Administrative Procedure Act to establish a policy on
allocating rights to power from the existing federal power system and
charging incremental rates may provide greater durability. If
established, such a rule would be implemented through subsequent
contract and ratemaking procedures and would be more difficult to
change than would an identical plan adopted in a record of decision.
In addition to growing pressure to provide power and financial
benefits, BPA has faced a changing business environment as the
electricity industry has undergone restructuring. These changes have
posed management challenges for BPA and highlighted areas that need
improvement. In particular, BPA's decision to serve demand beyond the
firm output of the federal power system at average rates puts the
agency at risk of becoming uncompetitive. Recognizing this
vulnerability, BPA has taken positive steps by developing a new
approach to managing its risks. Following through on this approach with
specific activities, resources, and time frames to fully implement its
risk management initiatives is crucial to BPA's ability to anticipate
and prepare for challenges to its overall competitiveness. Better risk
management should also help BPA in the future to avoid the kinds of
decisions that contributed to its recent financial difficulties.
Recommendations for Executive Action:
We recommend that the Administrator of BPA take the following four
actions:
To reduce the risk that BPA will be overcommitted in the future and to
help BPA control the costs of future power purchases, define the rights
to purchase the firm output of the federal power system so that:
* the amount of power that BPA sells at its lowest, cost-based rate is
equivalent to the firm output of the existing federal power system,
and:
* customers who demand additional power from BPA are charged
incremental rates that fully reflect the additional costs BPA incurs in
acquiring or otherwise providing such power.
As a way to lend credibility to and reinforce BPA's actions, study the
feasibility of issuing a rule under the Administrative Procedure Act to
define the rights to purchase the firm output of the existing federal
power system and set the terms of incremental rates for any power sold
beyond that amount.
To strengthen BPA's management plan and to ensure that progress is made
in implementing its new risk management approach, identify specific
activities, resources, and time frames to implement BPA's risk
management initiatives.
Agency Comments:
We provided BPA with a draft of this report for review and comment. BPA
generally concurred with our recommendations and said that the report,
as a whole, accurately portrays the advantages and disadvantages BPA
faces in marketing electricity as well as the root causes of its
financial difficulties and associated rate increases during the last
few years. Regarding our recommendation that BPA study the feasibility
of issuing a rule under the Administrative Procedure Act to define the
amount of power it sells at its lowest cost-based rate and to charge
incremental rates for additional power, BPA stated that it plans
instead to establish long-term contracts and rates under the terms of
section 7(i) of the Northwest Power Act, which apply to the
establishment of all BPA rates. However, this statement does not
directly address our recommendation. We continue to believe that it
would be prudent for BPA to consider the feasibility of issuing a rule
under the Administrative Procedure Act because such a rule would have
the force of law and could improve the durability of BPA's policy
decisions. Concerning our presentation of BPA's increasing average
annual internal operations costs associated with its power marketing
business for 1997 to 2003, BPA stated that the inclusion by GAO of
employee retirement costs in BPA's internal operations costs skews the
costs upward in the latter years because those years included catch-up
payments that accrued but were not paid in earlier years. We have
discussed this point in the report and acknowledged that a large part
of the increase in BPA's internal costs were the result of these catch-
up payments for employee retirement costs. However, we continue to
believe that including costs associated with employee retirement
payments presents a more complete picture of BPA's internal operations
costs since 1997 because these retirement payments represent a
significant increase in BPA's internal costs going forward. The
complete text of BPA's comments on our draft report is presented in
appendix IV. BPA also made technical clarifications, which we
incorporated in this report as appropriate.
As agreed with your offices, unless you publicly announce the contents
of this report earlier, we plan no further distribution of it until 30
days from the report date. At that time, we will send copies of this
report to interested Members of Congress and make copies available to
others upon request. In addition, the report will be available at no
charge on the GAO Web site at http://www.gao.gov.
If you have any questions about this report or need additional
information, please call me at (202) 512-3841. Key contributors to this
report are listed in appendix V.
Signed by:
Jim Wells:
Director, Natural Resources and Environment:
[End of section]
Appendix I: Scope and Methodology:
To address the overall objectives, we interviewed and obtained
documentation from Bonneville Power Administration (BPA) officials,
BPA's customers, and a variety of regional stakeholders. Among BPA's
customers, we interviewed representatives of public utilities from each
of the four primary states where BPA sells its power--including
representatives from small and large public utilities as well as urban
and rural public utilities. We also interviewed representatives of
investor-owned utilities and direct service industries in the region,
as well as members of state commissions regulating the investor-owned
utility customers of BPA. Among BPA's regional stakeholders, we
interviewed officials from the Northwest Power and Conservation
Council, Columbia Basin Fish and Wildlife Authority, Columbia River
Intertribal Fish Commission, Industrial Customers of Northwest
Utilities, Northwest Energy Coalition, and Renewable Northwest Project.
We also collected the views of several experts on the electricity
market in the Pacific Northwest and BPA's role in that market.
To determine the advantages and disadvantages that BPA faces in
marketing electric power in a more competitive environment, we
interviewed and obtained documentation from BPA and its major customers
and stakeholder groups. To compare BPA's power rates and generation
costs with those of other wholesale providers of electricity, we
obtained data from the Energy Information Administration and Platts'/
RDI PowerDat. In assessing the reliability of these data through (1)
interviews with knowledgeable officials and (2) electronic data
testing, we determined that the reliability of these data was adequate
to describe BPA's power rates and generation costs. To understand BPA's
financing mechanisms, we examined published and unpublished financial
data from BPA, interviewed BPA officials, and interviewed
representatives from Standard and Poors and Fitch Ratings. We also
reviewed pertinent laws and documents describing the history of the
federal power system.
To determine the major causes of BPA's recent cost increases, we
focused our review on the costs related to BPA's Power Business Line
that are included in the power rates that BPA charges its customers.
These costs differ from those available in BPA's annual reports, which
include costs for the entire agency. We reviewed publicly available
records that BPA produced to document the subscription and augmentation
processes, including its 1998 record of decision on its subscription
policy, rate cases filed in May 2000 and June 2001, and the April 2003
Report to the Region. We also interviewed BPA officials and reviewed
internal BPA documents related to its power purchase and buy-back
contracts. In assessing the reliability of data related to BPA's costs
through (1) review of related documentation, (2) interviews with
knowledgeable officials, and (3) electronic data testing, we determined
that the reliability of these data was adequate to describe BPA's costs
associated with its power marketing business. Where possible, we
compared data received from BPA with BPA's audited financial
statements. Finally, we interviewed Northwest Power and Conservation
Council officials, BPA customers, and other stakeholders to obtain
their views on the reasons for BPA's cost increases.
To determine the extent to which BPA has taken actions to control its
costs, we obtained relevant documentation and interviewed officials
from BPA, the Northwest Power and Conservation Council, the Corps of
Engineers, the Columbia River Intertribal Fish Commission, and the
Columbia Basin Fish and Wildlife Authority. To determine the steps BPA
has taken to improve its risk management process, we reviewed documents
related to risk management standards--including GAO's Standards for
Internal Control in the Federal Government, and Enterprise Risk
Management Framework, prepared by the Committee of Sponsoring
Organizations of the Treadway Commission--and reviewed relevant BPA
documents, including reports prepared by a consultant hired by BPA to
evaluate its risk management process and make recommendations for
improvement. We also examined the BPA Administrator's performance
contract and BPA's strategic plan as they related to BPA's risk
management process. In addition, we obtained documentation and
interviewed BPA officials on proposed changes to BPA's financial
information system--the Bonneville Enterprise System--that manages its
accounting data and budgetary allocations. However, we were unable to
obtain consistent information on the nature and need for BPA's proposed
changes, and thus could not determine to what extent these proposed
changes would allow BPA to control its costs.
We conducted our work from August 2003 through April 2004 in accordance
with generally accepted government auditing standards.
[End of section]
Appendix II: BPA's Costs Associated with Fish and Wildlife Programs:
This appendix provides details on BPA's costs associated with its fish
and wildlife programs for fiscal years 1985 to 2003. See table 1.
Table 1: BPA's Costs Associated with Fish and Wildlife Programs, Fiscal
Years 1985-2003:
Dollars in millions.
Year: 1985;
Direct program costs: $24.2;
BPA internal support costs[A]: $0;
Reimbursable costs: $30.3;
Capital investment costs: $30.0;
High priority/action plan costs[B]: $0;
Total: $84.5.
Year: 1986;
Direct program costs: $29.1;
BPA internal support costs[A]: $0;
Reimbursable costs: $35.2;
Capital investment costs: $32.8;
High priority/action plan costs[B]: $0;
Total: $97.2.
Year: 1987;
Direct program costs: $32.1;
BPA internal support costs[A]: $0;
Reimbursable costs: $43.0;
Capital investment costs: $41.3;
High priority/action plan costs[B]: $0;
Total: $116.4.
Year: 1988;
Direct program costs: $26.4;
BPA internal support costs[A]: $0;
Reimbursable costs: $26.7;
Capital investment costs: $43.5;
High priority/action plan costs[B]: $0;
Total: $96.6.
Year: 1989;
Direct program costs: $31.1;
BPA internal support costs[A]: $0;
Reimbursable costs: $31.9;
Capital investment costs: $43.1;
High priority/action plan costs[B]: $0;
Total: $106.1.
Year: 1990;
Direct program costs: $42.7;
BPA internal support costs[A]: $0;
Reimbursable costs: $30.5;
Capital investment costs: $44.7;
High priority/action plan costs[B]: $0;
Total: $117.9.
Year: 1991;
Direct program costs: $41.4;
BPA internal support costs[A]: $0;
Reimbursable costs: $30.5;
Capital investment costs: $48.0;
High priority/action plan costs[B]: $0;
Total: $119.9.
Year: 1992;
Direct program costs: $82.1;
BPA internal support costs[A]: $0;
Reimbursable costs: $34.8;
Capital investment costs: $51.3;
High priority/action plan costs[B]: $0;
Total: $168.2.
Year: 1993;
Direct program costs: $59.4;
BPA internal support costs[A]: $0;
Reimbursable costs: $36.5;
Capital investment costs: $64.2;
High priority/action plan costs[B]: $0;
Total: $160.1.
Year: 1994;
Direct program costs: $65.5;
BPA internal support costs[A]: $0;
Reimbursable costs: $40.9;
Capital investment costs: $71.9;
High priority/action plan costs[B]: $0;
Total: $178.3.
Year: 1995;
Direct program costs: $82.0;
BPA internal support costs[A]: $0;
Reimbursable costs: $41.5;
Capital investment costs: $73.0;
High priority/action plan costs[B]: $0;
Total: $196.5.
Year: 1996;
Direct program costs: $77.2;
BPA internal support costs[A]: $0;
Reimbursable costs: $39.9;
Capital investment costs: $82.4;
High priority/action plan costs[B]: $0;
Total: $199.4.
Year: 1997;
Direct program costs: $91.0;
BPA internal support costs[A]: $0;
Reimbursable costs: $39.8;
Capital investment costs: $84.5;
High priority/action plan costs[B]: $0;
Total: $215.3.
Year: 1998;
Direct program costs: $114.8;
BPA internal support costs[A]: $0;
Reimbursable costs: $39.8;
Capital investment costs: $81.1;
High priority/action plan costs[B]: $0;
Total: $235.7.
Year: 1999;
Direct program costs: $107.9;
BPA internal support costs[A]: $9.0;
Reimbursable costs: $42.0;
Capital investment costs: $82.2;
High priority/action plan costs[B]: $0;
Total: $241.1.
Year: 2000;
Direct program costs: $106.7;
BPA internal support costs[A]: $7.8;
Reimbursable costs: $39.8;
Capital investment costs: $81.7;
High priority/action plan costs[B]: $0;
Total: $236.0.
Year: 2001;
Direct program costs: $94.3;
BPA internal support costs[A]: $9.1;
Reimbursable costs: $43.9;
Capital investment costs: $79.7;
High priority/action plan costs[B]: $3.0;
Total: $230.0.
Year: 2002;
Direct program costs: $128.9;
BPA internal support costs[A]: $10.5;
Reimbursable costs: $51.9;
Capital investment costs: $57.5;
High priority/action plan costs[B]: $7.2;
Total: $256.0.
Year: 2003;
Direct program costs: $128.7;
BPA internal support costs[A]: $11.9;
Reimbursable costs: $52.6;
Capital investment costs: $56.7;
High priority/action plan costs[B]: $6.5;
Total: $256.4.
Source: GAO analysis of BPA data.
Note: In constant dollars, base year 2003.
[A] Prior to fiscal year 1999, these costs were included within direct
program costs but not shown separately.
[B] Special program implemented in fiscal year 2001 to help offset
fish losses resulting from the power emergency declarations caused by
the drought.
[End of table]
Definition of Cost Categories:
1. Direct program costs--These costs are the noncapital expenditures
for fish and wildlife activities funded directly by BPA as well as off-
site (not part of a federal power system facility) capital projects.
The activities funded are based on measures in the Biological Opinions
and the Council's Fish and Wildlife Program. Prior to fiscal year 1999,
this category also includes the part of the budget that BPA devotes
internally to fish and wildlife related support activities.
2. BPA internal support costs--These costs are BPA's internal
expenditures for program support as well as contracts and other
expenditures on behalf of the fish and wildlife program. Until fiscal
year 1999, these costs were included as part of the Direct Program.
They remain part of direct program costs but are now shown separately.
3. Reimbursable costs--These costs consist of the hydroelectric share
of operation and maintenance and other noncapital expenditures for fish
and wildlife related activities by the Corps of Engineers (Corps),
Bureau of Reclamation (Bureau), and U.S. Fish and Wildlife Service that
are funded by appropriations and then reimbursed to the U.S. Treasury
by BPA. In addition, this category includes the part of the Council's
operating budget allocated to fish and wildlife activities. These costs
are now funded under direct funding agreements signed with each of the
three agencies.
4. Capital investment costs--These costs consist of the projected
amortization, depreciation, and interest payments for (1) past fish and
wildlife related borrowing by BPA; (2) the portion of past fish and
wildlife capital investments by the Corps and Bureau for which BPA is
already obligated to repay the U.S. Treasury; (3) the hydroelectric
share of future fish and wildlife related capital investments by the
Corps and Bureau that will be funded by appropriations and then
reimbursed to the U.S. Treasury by BPA, based on activities called for
in the Biological Opinion, the Council's Fish and Wildlife Program, and
other authorities; and (4) other capital investments directly funded by
BPA borrowing that are based on activities called for in the Biological
Opinion and the Council's Fish and Wildlife program.
5. High-priority/action plan costs--Costs for a special program
designed to mitigate for damages to fish resulting from the 2001 power
system emergency. Criteria for projects included (1) addressing
imminent risks to the survival of one or more species listed under the
Endangered Species Act that represent a time-limited opportunity or are
broadly recognized as projects that would achieve direct anadromous
fish benefits; (2) are appropriate mitigation for the federal power
system and not in lieu of expenditures or actions authorized or
required by other entities and are otherwise consistent with the Power
Act; and (3) the proposed project had all planning, permitting, and
landowner agreements completed so that on-the-ground work could begin
not later than September 30, 2001.
[End of section]
Appendix III: BPA Costs Associated with Its Power Marketing Business,
Fiscal Years 1997-2003:
This appendix provides details on BPA's costs that are associated with
its power marketing business and are charged to its power rates for
fiscal years 1997 to 2003. (See table 2.) According to a BPA official,
these data are consistent with BPA's audited financial statements.
Table 2: BPA Costs Associated with Its Power Marketing Business, Fiscal
Years 1997-2003:
Dollars in millions.
Power purchases--short term;
1997: $66.4;
1998: $151.8;
1999: $288.2;
2000: $661.4;
2001: $2,191.1;
2002: $306.6;
2003: $228.8.
Power purchases--long term;
1997: $0;
1998: $0;
1999: $0;
2000: $0;
2001: $0;
2002: $456.0;
2003: $395.1.
Power buy-backs;
1997: $0;
1998: $0;
1999: $0;
2000: $0;
2001: $123.3;
2002: $461.7;
2003: $368.4.
Power system generation;
1997: $639.4;
1998: $647.9;
1999: $503.5;
2000: $477.2;
2001: $591.2;
2002: $641.8;
2003: $672.7.
Fish and wildlife;
1997: $109.4;
1998: $133.0;
1999: $136.3;
2000: $135.5;
2001: $127.1;
2002: $170.2;
2003: $170.3.
Internal operations;
1997: $102.4;
1998: $90.3;
1999: $99.7;
2000: $94.7;
2001: $115.5;
2002: $157.3;
2003: $115.0.
Transmission and ancillary services;
1997: $271.4;
1998: $303.8;
1999: $320.1;
2000: $261.7;
2001: $234.6;
2002: $193.1;
2003: $156.9.
Other;
1997: $896.2;
1998: $994.4;
1999: $1,074.5;
2000: $949.5;
2001: $1,020.9;
2002: $992.2;
2003: $932.1.
Total;
1997: $2,085.2;
1998: $2,321.2;
1999: $2,422.3;
2000: $2,580.0;
2001: $4,403.7;
2002: $3,378.9;
2003: $3,039.3.
Source: GAO analysis of BPA data.
Note: In constant dollars, base year 2003.
[End of table]
Definition of Cost Categories:
1. Power purchases (short term)--Costs of the power BPA purchases in
the short term to use the flexibility of the federal power system to
optimize its value and to provide operational stability to the system.
2. Power purchases (long term)--Costs of the power that BPA signed
contracts to purchase in 2002 and 2003 to meet demand beyond the firm
output of the federal power system.
3. Power buy-backs--Costs of buy-back payments that BPA made to
investor-owned utilities, direct service industries, and public
utilities in addition to power purchases.
4. Power system generation--Costs associated with operation and
maintenance costs for the federal dams, the nonfederal nuclear plant,
and long-term generating projects. Includes BPA expenditures for the
residential exchange program, energy conservation, and renewable energy
development. Also includes BPA's share of costs to decommission
nonoperating power projects and expenses for the benefits BPA receives
from storage projects in Canada. Does not include payments to investor-
owned utilities to buy back power BPA agreed to sell under a settlement
agreement of the residential exchange program; these costs are included
under power buy-backs.
5. Fish and wildlife--Costs associated with BPA's direct program, high
priority actions, the Northwest Power and Conservation Council, and
Lower Snake River Hatcheries. Direct program costs include BPA's direct
noncapital expenditures to protect, mitigate, and enhance fish and
wildlife affected by the development of the federal power system. The
activities funded are based on measures in the Biological Opinions and
the Council's Fish and Wildlife Program. Direct program costs also
include BPA's internal expenditures for program support. High priority
actions costs are for a program designed to mitigate for damages to
fish resulting from the 2001 power system emergency and designed to
address imminent risks to the survival of one or more species listed
under the Endangered Species Act. BPA funds the Northwest Power and
Conservation Council's annual operating budget, which averaged almost
$8 million per year, from fiscal year 1997 to 2003. Approximately half
its budget, including staff time, is dedicated to fish and wildlife
activities. Lower Snake River hatcheries costs include payments to the
U.S. Fish and Wildlife Service to fund fish hatcheries on the Snake
River.
6. Internal operations--Costs associated with BPA power nongeneration
operations, shared services and administration, and the civil service
retirement system. Power nongeneration operations costs include BPA's
portion of expenses related to the joint management of the federal
power system; oversight of the nonfederal nuclear project, development,
and administration of power contracts; tribal relationship management;
Canadian Treaty management; public involvement and policy development;
power rates setting, power financial management, and power billing;
short-term and long-term marketing and support; development and
management of conservation and energy efficiency programs; system
operations support (such as weather and stream flow forecasting,
scheduling, load forecasting); maintenance of automated systems for
Power Business Line application and system management; and projects to
improve overall performance and meet market challenges, such as
increasing forecasting capabilities to optimize federal power system
generation. Shared services and administrative costs include the costs
for information technology services; infrastructure and maintenance;
building rent, maintenance, and security; and mail services, personnel
services, library and printing services, as well as the portion of
corporate general and administrative costs allocated to power rates.
Civil service retirement system costs are associated with the unfunded
liability of the Civil Service Retirement and Disability Fund, the
Employees Health Benefits Fund, and the Employees Life Insurance Fund,
which had not been covered prior to fiscal year 1998. These costs also
include the power related portion of the Army Corps of Engineers,
Bureau of Reclamation, and the U.S. Fish and Wildlife Pension and Post-
retirement Benefits.
7. Transmission and ancillary services--Costs associated with services
necessary to support the transmission of energy from resources to
loads, including reliability, scheduling and dispatch, spinning
reserves, emergency reserves, load following and regulation, automatic
generation control, energy imbalance, transmission losses, control area
reserves for resources and for interruptible purchases.
8. Other--Include costs associated with the nonfederal debt service,
depreciation, amortization, net interest, and bad debt/expense
adjustment. Nonfederal debt service costs include BPA's portion of the
debt of Energy Northwest and various nonfederal conservation and
hydroelectric projects. Depreciation costs are the allocation of
expenses associated with property, plant, and equipment to each period
benefited by the asset. Depreciation is calculated by dividing the
costs of the asset, less any applicable salvage value, by its estimated
useful life or allowable period of time. Amortization costs are the
allocation of expenses associated with intangible capital investments,
such as for conservation and fish and wildlife. Net interest expense
costs are the net expenses resulting from money borrowed to construct
and maintain the federal power system and other projects. Costs
associated with bad debt expenses include money BPA did not receive
from parties who have declared bankruptcy. Expense adjustments
represent miscellaneous accounting entries not associated with specific
programs.
[End of section]
Appendix IV: Comments from the Bonneville Power Administration:
Department of Energy:
Bonneville Power Administration:
Washington, D.C. 20585:
JUN 22 2004:
In reply refer to: DC-Wash.
Mr. Jim Wells:
Director, Natural Resources and Environment:
United States General Accounting Office:
Washington, D.C. 20548:
Dear Mr. Wells:
The Bonneville Power Administration (BPA) appreciates the opportunity
the General Accounting Office (GAO) has provided us to review and
comment on the draft of your report entitled Bonneville Power
Administration: Better Management of BPA's Obligation to Provide Power
is Needed to Control Future Costs (GAO-04-694) and to discuss our
comments with GAO staff.
We also appreciate the extensive effort GAO has invested over the past
year to fully investigate these issues. We concur generally with your
recommendations and believe the draft report as a whole accurately
portrays the advantages and disadvantages BPA faces in marketing
electricity as well as the root causes of our financial difficulties
and associated rate increases during the last few years.
We do have a few observations that we hope will strengthen your report,
primarily related to progress we have made since April. We have also
attached a number of technical comments and suggestions.
Defining BPA's load obligation:
Your draft report recommends that BPA reduce its future risk of open-
ended load obligation by:
(1) limiting the amount of power we sell at our lowest cost-based rate
to the existing federal system firm output, and:
(2) charging incremental rates for any power sold beyond this amount
that fully reflect the additional costs BPA incurs in acquiring or
otherwise providing such power.
We concur and have made substantial progress in this area by advancing
our draft strategic plan.
The draft report states on page 32:
"In March 2004, BPA issued a draft strategic plan to define a direction
for the agency. As BPA established an objective of clarifying how much
power it will price, starting in fiscal year 2007. BPA's plan states
that it will establish, via long-term power contacts with its
customers, the base amount are able to buy at a low rate. If customers
request power beyond incremental rates to and power higher-cost
resources."
[See PDF for page 2 of Comments from the Bonneville Power
Administration]
[End of page 2 of Comments from the Bonneville Power Administration]
Rates and contracts together will define prices and rights to the firm
output of the existing federal power system and the incremental rates
and terms for supply beyond this base amount of existing federal power.
Managing risks systematically:
Your draft report recognizes BPA's planning and implementation of a
relatively new enterprise risk management framework. This approach
extends beyond risks associated with cost control and involves a more
rigorous approach to assessing and responding to risks that affect the
achievement of our strategic and financial objectives. Since your April
observation, BPA has continued to execute its risk improvements,
including making staff hires, convening management governance
committees, and establishing risk management work plans. We appreciate
GAO's support for our continued efforts in this area.
A technical point on conveying trends in BPA's internal operating
costs:
One technical detail of the report is particularly important to BPA.
The draft report states on page 30:
" ... BPA's average annual internal operations costs associated with
its power marketing business for 2001 to 2003 are 34 percent higher (or
$32 million, adjusting for inflation) than they were from 1997 to 2000,
largely because of new requirements regarding employee retirement costs
and increased demand placed on BPA during the current rate period."
As is noted in the draft report, GAO included Civil Service Retirement
System (CSRS) payments in power-related internal operations costs. CSRS
costs were first reflected in 1998 when the agency was made wholly
responsible for financing pensions of its employees and those of the
U.S. Army Corps of Engineers and Bureau of Reclamation associated with
the Federal Columbia River Power System. Because this new requirement
occurred in the middle of a rate period, BPA made less than full CSRS
payments from 1998-2001 with the agreement that it would make
substantial "catch up" payments beginning in 2002 when BPA re-
established power rates. To compensate for the skew created by these
catch-up payments and create an accurate comparison of period expenses,
we believe it is necessary to remove these costs from internal
operations expenses in both periods.
As you note in footnote number 17, using this approach, our internal
operations costs allocated to power were 10 percent lower in 2003 than
in 2001. Our 2004 power internal costs also will be below 2001 levels.
We believe this more accurately portrays trends in our internal
operating costs and is the basis for our ongoing commitment to the
region that we manage internal operations costs at or below 2001
actuals on average for the remainder of the rate period.
We have done our best in the time allowed to provide the attached
technical, editorial and policy comments. We believe the inclusion of
these comments will improve the accuracy of your report and will help
you improve the final product. BPA will include a link to the final
audit report and other relevant background information on our web site
at http://www.bpa.gov/corporate/about BPA/audits/
Again, thank you for allowing us the opportunity to comment on the
draft report.
Sincerely,
Signed by:
Jeffrey K. Stier,
Vice-President for National Relations:
Enclosure:
cc:
D. Hill, GC-70:
L. Novitsky, ME-1:
B. Porter, PML:
[End of section]
Appendix V: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Jim Wells (202) 512-3841:
Frank Rusco (202) 512-4597:
Staff Acknowledgments:
In addition to the individuals named above, Jill Berman, Jonathan Dent,
Samantha Gross, Jason Holliday, Jon Ludwigson, Don Neff, Cynthia
Norris, Eric Wenner, and Doris Yanger made key contributions to this
report. Important contributions were also made by Janice Lichty, Lisa
Shames, and Barbara Timmerman.
FOOTNOTES
[1] A critical water year is a year in which the annual runoff in the
Columbia River Basin is equivalent to the amount recorded in 1937, one
of the lowest on record.
[2] The others are the Southeastern Power Administration, the
Southwestern Power Administration, and the Western Area Power
Administration.
[3] BPA has generally used the term "tiered rates" to describe the rate
design that differentiates between a rate that applies to sales at the
lowest embedded-cost rate and a rate that applies to sales beyond that
amount.
[4] BPA sells secondary power at market prices, subject to a self-
imposed average annual price cap--this average annual price cap is
determined by the cost to BPA of power produced at the Energy Northwest
operated nuclear plant. BPA may actually receive more than this amount
when it sells its power in a formal market and when the market-clearing
price exceeds BPA's self-imposed price cap.
[5] An acre-foot is the volume of water necessary to cover one acre to
a depth of one foot and is equivalent to 325,851 gallons. A watt-hour
is a measurement equal to 1 watt of power supplied to, or taken from,
an electrical circuit steadily for 1 hour. A megawatt-hour is one
million watt-hours, or enough power to serve the needs of about 750
homes for 1 hour. An aMW is equal to 8,760 megawatt-hours, or the
average number of megawatt-hours over the course of 1 year (i.e., 24
hours x 365 days x 1 megawatt).
[6] Comprehensive Review of the Northwest Energy System--Final Report:
Toward a Competitive Electric Power Industry for the 21st Century,
December 12, 1996.
[7] We refer to this as appropriated debt because BPA is required to
repay appropriations used for capital investments, with interest.
However, these reimbursable appropriations are not technically
considered lending by the Treasury.
[8] At the time this debt was restructured, BPA's appropriated debt of
$6.85 billion carried a weighted-average interest rate of about 3.5
percent. Effective the first day of fiscal year 1997, the principal of
the outstanding debt was reduced to an estimated $4.29 billion and the
associated interest rate was increased to 7.1 percent.
[9] Figures are presented in constant dollars using 2003 as the base
year.
[10] At the time these agreements were made, Energy Northwest was known
as Washington Public Power Supply System, a joint operating agency in
the state of Washington made up of representatives of public utility
districts and municipalities. Under these agreements, BPA contracted to
pay all or part of the annual project budgets, including debt service,
whether or not the projects were completed.
[11] Some public utilities also can receive payments under this
program, but the cost to BPA is much smaller, averaging less than $23
million annually (in 2003 dollars) from 1982 to 2003.
[12] Average costs are in constant dollars, base year 2003. In 2002,
BPA began providing payments and power to investor-owned utilities
under a settlement agreement rather than under the residential exchange
provisions of the Northwest Power Act. The $210 million average
includes these costs.
[13] These estimates are adjusted for inflation using 2003 as a base
year.
[14] BPA officials told us that they are not required to track the
costs of irrigation water releases as they are with fish and wildlife
related releases. Therefore, they do not have annual figures for the
dollar impact on revenues of irrigation releases. According to BPA
officials, flood control, navigation, and recreational uses of the dams
do not have a significant affect on the amount of power BPA has to
sell.
[15] BPA is required by statute to set its rates to recover its costs.
Thus, when BPA's costs increase over time, its rates must increase by
an equal amount.
[16] The figure shows that in periods, such as in much of the 1970s,
when BPA's average nominal rates were nearly constant, inflation caused
the "real" or inflation-adjusted rates to fall, but that on average,
increases in BPA's rates exceeded inflation over the entire three
decades.
[17] These numbers have been adjusted for inflation, base year 2003.
This increase does not include the average annual cost to BPA of about
$245 million to buy back the majority of the 1,000 aMW of power it
agreed to provide to investor-owned utilities under the settlement
agreement, according to BPA officials.
[18] BPA has reported to its customers that its internal costs were 10
percent lower in 2003 than in 2001. In making this calculation, BPA
excluded the costs associated with the retirement costs it was not
previously required to pay. While BPA's calculation is correct, we
believe that including these costs presents a more complete picture of
BPA's expenses. In addition, since BPA's expenses in 2001 were already
higher than in previous years, we calculated BPA's average costs for
1997 to 2000 in order to determine how much BPA's internal operations
expenses have increased, on average, since 2001.
[19] According to BPA officials, BPA was required to cover these costs
beginning in 1998. However, BPA deferred payment until 2001, thus
increasing BPA's payments between 2001 and 2003.
[20] According to BPA officials, the use of long-term contracts is an
integral part of BPA's proposal and may be the best means to protect
U.S. taxpayers' investment in the federal power system.
[21] Northwest Power and Conservation Council, Recommendations on the
Future Role of the Bonneville Power Administration in Regional Power
Supply, May 2004.
[22] Bonneville Power Administration, Asset Management Strategy for the
Federal Columbia River Power System (Portland, OR., June 1999).
[23] BPA originally set a funding target for the direct program in the
2002 to 2006 rate period at $150 million annually, with the expectation
that actual expenses would average $139 million.
[24] Effective internal control should provide for an assessment of
risks an organization faces from both external and internal sources.
U.S. General Accounting Office, Standards for Internal Control in the
Federal Government, GAO/AIMD-00-21.3.1 (Washington, D.C.: November
1999).
[25] BPA has two main business lines--Power Business Line and
Transmission Business Line. These business lines are supported by
several corporate units that also carry out significant functional
responsibilities of the agency, such as the Environment, Fish, and
Wildlife group.
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